Electric power or utility plants generate electricity using any of a number of different types of power generation methodologies, and are typically categorized based on the type of raw energy they use to generate electrical power. Electrical power generation methodologies include, for example, thermal, nuclear, wind, and hydroelectric energy conversion methodologies, to name but a few. While the electric utility plants which use these various different types of power generation methodologies operate using different implementation technologies, these plants are always operated under a set of constraints applicable to the particular methodology being applied. For example, the electrical output of a thermal generator is a function of the amount of heat generated in a boiler, wherein the amount of heat is determined by the amount and type of fuel that is burned per hour. An output of a nuclear power plant is likewise dependent on the control of a nuclear fission reaction using control rods to dampen the fission process so as to create a desired level of radiation and, therefore, heat. In most cases, control of the particular operating characteristics of the plant within a range of possible operating characteristics allowed by the constraints can be performed to run the plant in a more optimal manner, such as to maximize the efficiency of the electrical generation within the plant, to minimize the cost of operating the plant, etc. However, in many cases, such optimization is performed, at best, in an ad hoc manner.
Thermal based electrical power generation plants are the most common types of utility power plants. As is known, the output of a thermal generator is dependent upon the heat transfer efficiency of the boiler used to burn fuel. In particular, fuel burning electric power generators typically operate by burning fuel to generate steam from water traveling through a number of pipes and tubes in the boiler. Here, the steam is used to drive one or more steam turbines which, in turn, create electrical energy. To maximize the use of the heat generated in the thermal process, a utility plant boiler typically contains cascaded heat exchanger sections, wherein the heat exiting from one heat exchanger section enters the following heat exchanger section. One example of constraints encountered in these types of plants (i.e., power plants using boilers or other similar steam generation technologies) that affects the efficiency of the plant includes the set points of the steam temperature used at the final super-heater and re-heater outlets of the boilers. Typically, these set points are kept constant, and it is necessary to maintain steam temperature at these points close to the set-points within a narrow range at all load levels regardless of the fuel flow to the boiler. In fact, in the operation of electric utility boilers, control of steam temperature is critical, as it is important that the temperature of steam exiting a boiler and entering a steam turbine is at an optimally desired temperature. If the steam temperature is too high, it may cause damage to the blades of the steam turbine for various metallurgical reasons. On the other hand, if the steam temperature is too low, it may contain water particles which may also cause damage to components of the steam turbine. In these types of power plants, control of the steam temperature is often achieved by spraying saturated water into the steam fluid at a point before the final heat exchanger section, i.e., the heat exchanger section located just before the steam turbine. Various temperature sensors are provided in and between the heat exchanger sections to measure the steam temperature, and the measured steam temperature is used to determine the amount of saturated water spraying which takes place. The operation of the plant can typically be optimized, however, by controlling the fuel flow to the boiler and the spraying of the water within the heat exchanger sections in a manner that keeps the steam temperatures at the desired set points while using the minimal amount of fuel.
In any event, as noted above, thermal as well as nuclear utility plants generally implement a steam cycle in which steam is generated in a boiler or a nuclear reaction vessel and is provided to one or more steam turbines. In most cases, pipes direct the steam exiting the turbines to one or more condensers, which cool the steam, returning it to liquid form, and this liquid is then returned to and reheated in the boiler or other steam generator. Many different types of condensers can be used to cool the steam, with the most common or prevalent type of condenser being a water cooled condenser, such as that used in many once-through water cooling systems or in closed re-circulating water cooling systems. In most once-through water cooled systems, external cooling water, such as sea water, river water or lake water is pumped through a heat exchanger within the condenser. Heat from the steam is transferred to the cooling water within the heat exchanger, and the cooling water is then returned to the sea, river, lake or other source from which it was taken. In a closed re-circulating water cooling system, the cooling water exiting the condenser is pumped, for example, to an evaporation unit, where the water is cooled and is re-circulated back to the heat exchanger in the condenser.
As is known, the majority of the new or fresh water used in a power plant that uses water cooled condenser systems is used in the condenser cooling cycle. In fact, many older power plants that use once-through cooling heat large volumes of water and then return that water, with little volume loss, to a river, a lake, or an ocean. Unfortunately, water is often a limited or scarce resource, and thus may not be in sufficient supply at any particular power plant site. Many countries, such as China, are very concerned about stressing water supplies and so have limited the use of water in these types of power plants. In some regions, especially dry and arid regions, the use of lake and river water is tightly regulated, and so it may not be possible, or it may be very costly to use a large amount of fresh water in a power plant cooling system. Still further, once-through cooling systems, while consuming very little water because they return most of the water to the source, still heat up the water, which in many cases leads to undesirable environmental impacts. For example, a 2002 EPRI report found that a typical once through water cooling system at a plant burning a fossil fuel, biomass, or waste requires withdrawals of 20,000 to 50,000 gal./MWh (gallons per megawatt-hour), although it only consumes (loses) 300 gal./MWh. However, the large volume of water withdrawn by a once-through cooling system can entrain and impinge aquatic organisms, and discharges heat to surface waters which may have adverse ecological effects. As a result, most United States jurisdictions now discourage or prohibit construction of new power plants that use once-through water cooling systems.
As a result, more and more new power plants are designed to use closed-loop (re-circulating) cooling systems in which re-circulating water is used to cool the steam in the condenser and is then itself cooled using, for example, an evaporative process. However, because re-circulating cooling systems cool by evaporation in towers or cooling ponds, they consume more water than once-through cooling systems. While the actual rates of water withdrawal and consumption depend on the power generation technology and the particular environmental conditions associated with a particular plant, a typical plant using a closed-loop cooling system requires withdrawals of just 500 to 600 gal./MWh but loses 480 gal./MWh to evaporation, according to the 2002 EPRI report.
While the cost of acquiring and delivering cooling water to these types of plants can vary, this cost is not insignificant. Moreover, in re-circulating cooling systems, the cost to treat and dispose of cooling water varies much more widely, depending on the characteristics of the raw water being used. For example, surface water may be suitable for cooling with minimal treatment or may only require removal of suspended solids. While effluent from wastewater treatment plants, which is typically treated to make it suitable for discharge, is usually of fairly high quality, nutrients and bacteria may restrict the use of wastewater in a cooling system unless this water is pre-treated in the power plant. Even fresh groundwater can have high concentrations of dissolved solids that can become scale unless they are removed by pre-treatment in a closed-loop cooling system. Saline water from the ocean or coastal areas also requires treatment and/or the use of special corrosion-resistant materials to make it suitable for use in a power plant. Degraded waters from coal and oil production may be available for use in a plant cooling system, but these types of water have much greater pre-treatment requirements. For example, low pH is an issue for water pumped from spent coal mines, and the effluent of oil and gas well operations can have high levels of salts, silica, and hardness. Thus, many sources of water must be pre-treated to be used in a re-circulating water cooling system. Moreover, because re-circulating cooling water also concentrates dissolved constituents in a cooling tower or a cooling pond, this water may need to be post-treated if it is to be discharged to surface waters.
In any event, because water is becoming a scarce commodity, and the use of water in re-circulating cooling systems can be expensive, plant designers are, more and more, considering direct dry cooling systems, also called air cooled condensers. Generally speaking, direct dry cooling systems condense turbine exhaust steam inside a set of finned tubes, which are externally cooled by ambient air instead of surface water or re-circulating water. In these dry cooling systems, ambient air is circulated within the condenser to perform cooling either using a natural draft system or using electric fans.
A natural draft system uses a hyperbolic tower that can exceed, for example, 300 feet in height, with a series of heat exchangers disposed at the bottom thereof. In this system, ambient air enters the bottom periphery of the tower, passing over heat exchanger elements. The heated air naturally rises inside the tower, which causes a draft at the bottom of the tower, pulling in more cool air at the bottom of the tower. Importantly, no fans are required. However, the large size of the hyperbolic tower makes the natural draft option a niche application and this type of cooling system is typically only able to be economically used at small power plant sites.
The other, more familiar direct dry cooling design includes the use of air cooled condensers which operate using electrical motor-driven fans that drive the ambient air through the finned tube structures of the condenser. Because this type of condenser system can be used in practically any location without the attendant cost of the tower, about 90 percent of the dry-cooled power plants in the world use air cooled condensers with mechanical draft, i.e., electric fans. Moreover, these types of air cooled condensers have been used on both combined cycle plants and large fossil fuel plants.
When designed, the electrically driven air cooled condensers of a particular plant are sized according to maximum design conditions, the highest load indexes and the most severe environmental conditions (e.g., the highest temperatures) expected within or at the plant. At these conditions, all of the fans of the air cooled condensers typically need to be run to perform the necessary cooling within the condensers. However, the fans of the air cooled condensers may be controllable to some extent. For example, the fans of the air cooled condensers may be designed and installed with variable frequency drives (VFD) to enable continuously varying the speed of the fan, or these fans may be installed as fixed speed fans that can be run at two or more fixed speeds to allow for turn-down of the fans. Single speed fans do exist, however, as they create a lower installed cost, which is sometimes the only concern of the plant designer. In any event, if single speed, multiple speed or continuously variable speed fans are used within a plant, the optimum combination of fans to run in any particular situation other than the designed maximum load condition, and speed at which to run these fans to obtain the appropriate cooling within the re-circulating system is generally unknown and not easily predicted, as it involves solving for an elusive multidimensional point in the operational space of the cooling system. Moreover, changing the speed of and the number of fans running within a condenser system may change the backpressure at the steam turbine, resulting in a less than expected or designed heat rate, which is typically used as the measure of plant efficiency.
Thus, while utility plants that use electric powered air cooled condensers are designed to have enough fans to operate at full load and at the worst ambient conditions (e.g., the highest ambient temperature, worst humidity, etc.), operators generally do not have any ability to gauge how many fans to use, and at what speed to run the fans, at lower then maximum load and/or at more favorable ambient conditions. As a result, to be safe, operators tend to run all of the fans or to make a conservative guess as to how many fans to run at less than full load conditions. Unfortunately, running the electric fans of the air cooled condensers uses electric energy (created by the plant) and thus reduces the final output of the electric plant, thereby increasing the cost of the electrical power generation being performed. Standard methods of operating the air cooled condensers therefore typically result in a plant being less efficient than is possible, resulting in higher costs to run the plant for a given energy output. Combining the fact that condenser losses are among the largest controllable losses in a steam cycle utility power plant with the fact that circulating water for the condenser cooling cycle is the largest user of water at a power plant and the fact that water is often a scarce commodity, results in a need for better optimization of power plants that use air cooled condensers.